U.S. patent application number 10/671807 was filed with the patent office on 2005-03-31 for method of reducing sulfur in hydrocarbon feedstock using a membrane separation zone.
Invention is credited to Balko, Jeffrey William.
Application Number | 20050067323 10/671807 |
Document ID | / |
Family ID | 34376190 |
Filed Date | 2005-03-31 |
United States Patent
Application |
20050067323 |
Kind Code |
A1 |
Balko, Jeffrey William |
March 31, 2005 |
Method of reducing sulfur in hydrocarbon feedstock using a membrane
separation zone
Abstract
A membrane is used in combination with fractionation and
hydrodesulfurization to reduce the sulfur content of hydrocarbon
feeds, preferably sulfur-containing naphtha feeds. A membrane
separation zone is employed to treat a fraction of effluent from a
fractionation zone containing sulfur-containing non-aromatic
hydrocarbons to produce a sulfur rich permeate and sulfur deficient
retentate. The sulfur rich permeate and a second fraction of the
fractionation zone, which contains sulfur-containing aromatic
hydrocarbons, are further treated in a hydrodesulfurization zone.
The stream from the hydrodesulfurization zone and the sulfur
deficient retentate from the membrane separation zone are then
processed as low sulfur hydrocarbon streams, especially those
streams being processed in the manufacture of gasoline when the
initial hydrocarbon stream is naphtha from a fluidized catalytic
cracking unit.
Inventors: |
Balko, Jeffrey William;
(Annapolis, MD) |
Correspondence
Address: |
Charles A. Cross
W.R. Grace & Co.-Conn
Patent Dept.
7500 Grace Drive
Columbia
MD
21044-4098
US
|
Family ID: |
34376190 |
Appl. No.: |
10/671807 |
Filed: |
September 26, 2003 |
Current U.S.
Class: |
208/208R ;
208/211; 585/818 |
Current CPC
Class: |
C10G 69/02 20130101;
C10G 53/16 20130101; C10G 25/003 20130101; C10G 53/08 20130101;
C10G 69/14 20130101 |
Class at
Publication: |
208/208.00R ;
208/211; 585/818 |
International
Class: |
C10G 067/02; C10G
067/16 |
Claims
It is claimed:
1. A process for reducing sulfur content in a hydrocarbon feedstock
containing sulfur, the process comprising: (a) contacting the
hydrocarbon feedstock with a Fractionation Zone to produce at least
Fraction (1) and Fraction (2), wherein each fraction contains
sulfur, and Fraction (1) has a final boiling point that is lower
than that of Fraction (2), (b) contacting Fraction (1) with a
Membrane Separation Zone, said Membrane Separation Zone containing
a membrane having a sufficient flux and selectivity to separate a
sulfur-enriched permeate fraction and a sulfur deficient retentate
fraction, and said sulfur enriched permeate fraction being enriched
in sulfur compared to Fraction (1); (c) recovering the sulfur
deficient retentate fraction; (d) contacting said sulfur enriched
permeate fraction of (b) and said Fraction (2) of (a), separately
or as a combination, with a Desulfurization Zone to reduce the
sulfur content of the sulfur enriched permeate fraction and
Fraction (2); and (e) recovering a hydrocarbon stream from the
Desulfurization Zone wherein the hydrocarbon stream has a reduced
sulfur content, relative to the sulfur-containing feedstock.
2. A process according to claim 1 wherein the membrane in (b)
comprises a member selected from the group consisting of polyimide,
polyurea-urethane, polysiloxane and combinations thereof.
3. A process according to claim 1 wherein the membrane in (b)
comprises a polyurea-urethane.
4. A process according to claim 1 wherein the hydrocarbon feedstock
is a naphtha feed.
5. A process according to claim 4 wherein the naphtha feed contains
at least 150 ppm sulfir.
6. A process according to claim 4 wherein the naphtha feed is an
effluent from a fluidized catalytic cracking unit.
7. A process according to claim 1 wherein Fraction (1) and Fraction
(2) are produced in the Fractionation Zone of step (a) under
catalytic distillation conditions.
8. A process according to claim 1 wherein Fraction (1) has a final
boiling point in the range of about 50.degree. C. to about
200.degree. C.
9. A process according to claim 1 wherein Fraction (1) has a final
boiling point in the range of about 50.degree. C. to about
130.degree. C.
10. A process according to claim 1 wherein Fraction (1) contains
sulfur-containing aromatic hydrocarbons.
11. A process according to claim 8 wherein Fraction (1) contains
sulfur-containing aromatic hydrocarbons.
12. A process according to claim 4 wherein Fraction (1) contains
sulfur-containing aromatic hydrocarbons.
13. A process according to claim 7 wherein Fraction (1) contains
sulfir-containing aromatic hydrocarbons.
14. A process according to claim 10 wherein Fraction (1) contains
thiophene or alkylthiophene.
15. A process according to claim 11 wherein Fraction (1) contains
thiophene or alkylthiophene.
16. A process according to claim 12 wherein Fraction (1) contains
thiophene or alkylthiophene.
17. A process according to claim 13 wherein Fraction (1) contains
thiophene or alkylthiophene.
18. A process according to claim 17 wherein Fraction (1) is
substantially free of mercaptan-containing compound.
19. A process according to claim 1 wherein Fraction (2) contains a
member selected from the group consisting of benzothiophene,
alkylbenzothiophene, and thioethers.
20. A process according to claim 1 wherein the sulfur deficient
retentate fraction of step (b) contains 70 ppm or less sulfur.
21. A process according to claim 1 wherein the Membrane Separation
Zone operates under pervaporation conditions.
22. A process according to claim 1 wherein the membrane has a
sulfur enrichment factor of at least 1.5.
23. A process according to claim 1 wherein sulfur deficient
retentate fraction of (b) is transferred as a gasoline blend
stock.
24. A process according to claim 1 wherein the Desulfurization Zone
of (d) operates under hydrodesulfurization conditions.
25. A process according to claim 1 wherein the Desulfurization Zone
of (d) operates under catalytic hydrodesulfurization
conditions.
26. A process according to claim 25 wherein the sulfur content of
reduced sulfur-containing hydrocarbon streams from the
Desulfurization Zone in (f) is 50 ppm or less sulfur.
Description
FIELD OF THE INVENTION
[0001] This invention relates to methods of reducing sulfur content
in sulfur-containing hydrocarbon feedstock, and more particularly,
relates to methods that employ membranes.
BACKGROUND OF THE INVENTION
[0002] Environmental concerns have led to decreases in the
permissible levels of sulfur in hydrocarbon fuels. Sulfur in
refinery streams, e.g., feedstocks, is present in a number of
different forms, including aliphatic and aromatic compounds.
Sulfur, however, tends to be concentrated in the higher boiling
fractions, mainly in the form of aromatic heterocycle compounds
such as benzothiophenes, and dibenzothiophenes
[0003] Refiners have employed catalytic hydrodesulfurization
processes to reduce sulfur in hydrocarbon fuel feedstock.
Conventional hydrodesulfurization processes are capable of removing
sulfur compounds, especially the lower molecular weight materials
including mercaptan sulfur-containing aliphatic materials and
thiophenes to levels of <30 ppm. Hydrodesulfurization processes
can also reduce the more refractory sulfur compounds, but only at
higher desulfurization severities, increased cost and with greater
difficulty.
[0004] Petroleum refiners are now in the process of devising
methods for making ultra low sulfur gasoline in order to comply
with increasingly stringent environmental regulations. In certain
countries, regulations require refiners to produce gasoline
containing 50-ppm sulfur or less by 2005, and in some countries
refiners may have to produce gasoline containing less that 10-ppm
sulfur beginning in 2008. Some countries have already introduced
tax-incentives for 10-ppm gasoline sulfur levels. Regulations
requiring these ultra low sulfur levels will incur great expense in
terms of capital expenditures and increased refinery operating
costs if the refiner relies on current hydrodesulfurization
technology.
[0005] Refiners are considering several factors when designing new
processes and facilities for meeting these new regulations. Those
factors include the required level of sulfur reduction, existing
refinery equipment that might be retrofitted/used, overall cost,
operational flexibility, simplicity of reconstructing the plant for
possible lower sulfur specifications in the future and commercial
operating experience of the technology to be used.
[0006] Many refiners, particularly those with FCC units producing
gasoline having high sulfur levels, have already made strategy and
investment decisions for 50-ppm sulfur gasoline. One process being
considered by refiners with FCC units is CDTECH, Inc.'s two-zone
unit comprising a CDHydro unit and a CDHDS unit. In particular,
CDHydro and CDHDS are used to selectively reduce sulfur in naphtha
feedstock leaving a fluidized catalyst cracking (FCC) unit with
minimum octane loss which is typically seen when employing other
catalytic hydrodesulfurization processes to reduce sulfur content.
The CDTECH process treats light, mid and heavy cat naphthas (LCN,
MCN, HCN), with each fraction treated under optimal sulfur
reduction conditions.
[0007] The overall CDTECH process begins in the CDHydro unit
wherein the FCC naphtha is subject to catalytic distillation. The
CDHydro is designed to fractionate the naptha into a low sulfur,
low boiling point fraction and a higher sulfur content, higher
boiling point fraction. More specifically, catalyst is provided in
the CDHydro unit to catalyze the reaction of sulfur-containing
aliphatics, e.g., mercaptans, with excess diolefins to produce
heavier thioether compounds that will not fractionate with the
lighter boiling olefin overhead. The remaining diolefins are
partially saturated to olefins by reaction with hydrogen, which is
also present in the first zone. The conditions of the CDHydro unit
are set at endpoints of about 70.degree. C. so that higher boiling
point sulfur species, such as thiophenes and benzothiophenes, in
the FCC naptha will not fractionate as part of the lighter boiling
point overhead. These species, along with the thioethers, will be
present in the CDHydro high boiling bottoms product.
[0008] Bottoms from the CDHydro column are then fed to a second
zone, i.e., a CDHDS column, where the bottoms are catalytically
desulfurized in the presence of hydrogen. The hydrodesulfurization
conditions are optimized to achieve the desired sulfur reduction
with minimal olefin saturation. Olefins are concentrated at the top
of the CDHDS column, where conditions are mild, while sulfur is
concentrated at the bottom where the conditions result in very high
levels of hydrodesulfurization.
[0009] The product streams from the two zones are stabilized
together or separately, as desired, resulting in product streams
appropriate for their subsequent use.
[0010] While the CDTECH process has shown to effectively reduce
sulfur in naphtha feeds, they do require significant capital
investment and relatively high operating costs, with a significant
portion of these costs relating to the CDHDS unit and its
operation. Furthermore, only 40% of FCC gasoline is passed into
CDHydro's overhead, thereby subjecting a significant portion of the
FCC gasoline's olefin content to hydrogen and saturation in the
CDHDS zone. Accordingly, refiners selecting a CDTECH process to
meet the new sulfur regulations are facing significant
expenses.
[0011] Membrane processes have also been suggested for reducing
sulfur content in hydrocarbon feedstocks. Published patent
application 2002/0153284, published on Oct. 24, 2002, describes
employing membranes to reduce sulfur content of a naphtha
feedstream from a FCC unit. A membrane is selected so that when the
sulfur-containing naphtha is contacted with the membrane, a sulfur
rich permeate is created on one side of the membrane while a sulfur
deficient retentate is created on the other side of the membrane.
The retentate is then processed further as a low sulfur product
stream, while the permeate is routed to a traditional sulfur
reduction unit. Membrane units, usually in the form of modules, are
relatively inexpensive, and are an excellent choice for those
refiners who have not yet invested capital in another type of
sulfur reduction. Currently available membranes, however, do not
remove certain sulfur species, e.g., mercaptans, as effectively as
aromatic sulfur species. There may be a benefit of employing other
technologies with membranes when faced with removing significant
amounts of mercaptans.
[0012] For those refiners who have already selected a capital
intensive sulfur reduction process, it would be highly desirable to
find a way to defray and/or reduce the costs of the process, either
by lowering costs to operate the equipment, reducing the wear and
tear on the same or reducing the cost of replacement equipment when
a piece of equipment has failed. Additionally, it is expected that
the requirement to debottleneck the capital intensive sulfur
reduction process will create opportunities for new less expensive
processes used in concert with the originally selected
technologies.
SUMMARY OF THE INVENTION
[0013] A process for reducing sulfur content in a sulfur-containing
hydrocarbon feedstock has been developed where fractionation and
desulfurization zones, e.g., those used in the afore-mentioned
CDTECH process, can be operated more efficiently by employing a
Membrane Separation Zone.
[0014] The process comprises contacting the sulfur-containing
hydrocarbon feedstock with the Fractionation Zone to produce at
least two sulfur-containing fractions, Fraction (1) and Fraction
(2), wherein Fraction (1) has a lower boiling point than Fraction
(2). A Membrane Separation Zone is used to further treat Fraction
(1). The membrane has a sufficient flux and selectivity to separate
a sulfur rich permeate fraction and a sulfur deficient retentate
fraction, the relative sulfur content of each fraction being
compared to the sulfur content in Fraction (1). The sulfur
deficient retentate can be processed as a low sulfur blendstock.
The sulfur enriched permeate fraction and Fraction (2) from the
Fractionation Zone are contacted with a Desulfurization Zone to
reduce the sulfur content of those fractions. These fractions can
be introduced to the Desulfurization Zone separately or as a
combination. A reduced sulfur-containing hydrocarbon stream is then
recovered from the Desulfurization Zone and processed as a low
sulfur hydrocarbon stream. It has been found that one can obtain
overall sulfur levels of 50-ppm or less using the process, yet also
allows for a more overall cost effective operation of the
process.
[0015] In a preferred embodiment, the Fractionation Zone is a
catalytic distillation zone wherein low boiling sulfur-containing
species such as mercaptans are catalytically reacted to prevent
them from boiling into Fraction (1). The conditions used in the
Fractionation Zone of this invention can be adjusted to drive a
greater volume of Fraction (1) and other higher boiling
sulfur-containing species, e.g., thiophenes or alkylthiophenes,
which are then contacted with the membrane, thereby reducing the
fraction volume and amount of sulfur species in Fraction (2). The
adjusted conditions are also conducive to driving more olefinic
species to Fraction (1), which in turn are retained in the sulfur
deficient retentate and processed without having to be contacted
with the Desulfurization Zone where octane loss can occur through
hydrogenation of the olefins.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] FIG. 1 is a schematic illustration of the invention
processing a sulfur-containing naphtha feedstock.
[0017] FIG. 2 is a graph illustrating the flux and temperature
conditions in a Membrane Separation Zone of this invention that is
operating under pervaporation conditions.
[0018] FIG. 3 is a graph illustrating sulfur content in membrane
retentate at certain stage cuts and the corresponding sulfur
reduction using a Membrane Separation Zone of the invention.
[0019] FIG. 4 is a bar graph illustrating olefin content of the
membrane retentate generated by a Membrane Separation Zone of the
invention.
DETAILED DESCRIPTION
[0020] Sulfur-containing hydrocarbon feedstocks that can be treated
according to this invention are naphtha streams from a FCC unit.
The naphtha feed is in a liquid or substantially liquid form.
Sulfur in naphtha and other refinery streams comes in different
forms. For the purposes of this invention, the forms are classified
as sulfur-containing aromatic hydrocarbons and sulfur-containing
non-aromatic hydrocarbons. Preferably, the naphtha is not
hydrotreated prior to use in the inventive process. Typically, the
hydrocarbon streams will contain greater than 150-ppm, more
typically from about 150-ppm to 3000-ppm, and more frequently from
about 300 to about 1000-ppm, sulfur. The process of this invention
is particularly useful in refining those crudestocks known to have
a relatively large amount of these sulfur species. Such crudestocks
include heavy sour Canadian, Mexican and Venezuelan crudes.
[0021] For purposes of this invention, the term "naphtha" is used
herein to indicate hydrocarbon streams found in refinery operations
that have a boiling range between about 50.degree. C. to about
220.degree. C. The naphtha fractions contain various amounts of
olefinic, aromatic, and non-aromatic, e.g., aliphatic, hydrocarbon
compounds and are primarily differentiated by the following boiling
ranges. Light naphthas have a boiling point ranging from 50.degree.
C. to about 105.degree. C. Middle (mid) naphtha has a boiling point
ranging from 105.degree. C. to about 160.degree. C. Heavy cat
naphtha has a boiling point ranging from about 160.degree. C. to
about 220.degree. C.
[0022] The term "aromatic hydrocarbon compounds" is used herein to
designate a hydrocarbon-based organic compound containing one or
more aromatic rings, e.g. fused and/or bridged. An aromatic ring is
typified by benzene having a single aromatic nucleus. Aromatic
compounds having more than one aromatic ring include, for example,
naphthalene, anthracene, etc. Aromatic hydrocarbons that are
typically found in feedstocks to be treated by this invention
include those having 1 to 2 aromatic rings. Typical
sulfur-containing aromatic hydrocarbons include, but are not
limited to, thiophene, alkylthiophenes, benzothiophene and
alkylbenzothiophenes.
[0023] The term "non-aromatic hydrocarbon" is used herein to
designate a hydrocarbon-based organic compound having no aromatic
nucleus.
[0024] For purposes of this invention, the term "hydrocarbon" is
used to mean an organic compound having a predominately hydrocarbon
character. It is contemplated within the scope of this definition
that a hydrocarbon compound may contain at least one
non-hydrocarbon radical (e.g., sulfur or oxygen) provided that said
non-hydrocarbon radical does not alter the predominant hydrocarbon
nature of the organic compound. Typical sulfur-containing
non-aromatic hydrocarbons include, but are not limited to, low
molecular C2-C7 aliphatics, e.g., mercaptans compounds, sulfides
and thiophenols.
[0025] As already discussed, the process of this invention is
particularly suitable for reducing sulfur in FCC naphtha but it is
also suitable for reducing sulfur in hydrocarbon stocks found in
other areas of the refining process, or in areas outside
refining.
[0026] FIG. 1 illustrates processing a sulfur-containing naphtha
feedstock from an FCC unit. The naphtha is contacted with the
Fractionation Zone where at least two fractions are created.
Fraction (1) has a lower boiling point than Fraction (2). Fraction
(1) is contacted with the Membrane Separation Zone 2, and Fraction
(2) is transferred and contacted with Desulfurization Zone 3. The
Membrane Separation Zone divides Fraction (1) into a sulfur
enriched permeate and a sulfur deficient retentate, with the former
contacted with Desulfurization Zone 3 and the latter further
processed to produce gasoline blend stock. The effluent from
Desulfurization Zone (3) is also later processed as a low sulfur
gasoline blend stock. Each of the zones and details of their
operation follow.
[0027] Fraction Zone
[0028] As mentioned earlier, sulfur reduction processes that employ
a combination of catalytic distillation and catalytic
hydrodesulfurization are currently in use and sold by CDTECH Inc.
When employing the CDTECH process in the process of this invention
it is preferable that the CDHydro process be used as the
Fractionation Zone. CDHydro is a catalytic distillation tower that
is designed to produce low sulfur overhead product, with that
product referred to as overhead because that product is the lighter
boiler fraction driven off by the distillation tower.
[0029] In one embodiment of the invention all of the FCC naphtha is
fed to the CDHydro column. The C.sub.5 and C.sub.6 petroleum
compounds boil off and head up through catalyst mounted in the
column, along with hydrogen, which is also injected in the bottom
of the column. Naphtha feed that is fed to the CDHydro is
preferably not hydrotreated to hydrogen sulfide, and is instead
preferably subjected to catalytic treatment, wherein
mercaptan-containing compounds in the feed are catalytically
reacted with dienes in the naphtha feed to form thioethers. For the
purposes of this invention a mercaptans includes compounds R--SH
wherein R is a hydrocarbon. Their higher boiling temperature causes
the thioethers to fall to the bottom of the column. The thioethers
join the heavier petroleum compounds at the bottom of the column
and are sent to the CDHDS column. Because the pressure and
temperature of the catalytic distillation column is much lower than
conventional hydrotreating, saturation of olefins is reduced to
very low levels (according to CDTECH, the saturation which does
occur is desirable to eliminate diolefins). Thus, little excess
hydrogen is consumed. Producing a low sulfur overhead product from
the CDHydro in the CDTECH process requires an overhead product
endpoint of about 70.degree. C. in order not to drive the higher
boiling sulfur-containing aromatic hydrocarbons, e.g. thiophene,
into the overhead.
[0030] The process of this invention, however, does not require
limiting the boiling endpoint to such a low temperature. For most
refiners, it is indeed an advantage to drive more FCC gasoline
volume into the overhead in order to thus decrease the amount of
olefins running through desulfurization, e.g., hydrodesulfurization
like CDHDS. Accordingly, the Fractionation Zone of this invention
is operated under conditions sufficient to at least drive both
olefins and sulfur-containing aromatic hydrocarbons, e.g.,
thiophene and alkylthiophene, into the overhead product.
Accordingly, the Fractionation Zone of this invention can be
operated such that the overhead material has a final boiling point
of up to 200.degree. C. Pressures in the zone are in the range of
100 to 500 psi. The final boiling point of the overhead depends on
a number of factors, including the temperature and pressure profile
of the zone as the material travels through the zone, reflux ratio
and internal structure of the zone, internal structure including
catalyst packing configurations and catalyst trays. These factors
can all be adjusted using conventional techniques to produce an
overhead having a final boiling point as high as 200.degree. C. For
the purpose of this invention, "final boiling point" is that
boiling point of the heaviest fraction in the overhead. Catalysts
suitable for use in these zones comprise typical hydrotreating
catalysts such as NiMo, CoMo supported on aluminas the compositions
and manufacture of which are known to those skilled in the art
[0031] Operating the Fractionation Zone under the above conditions
creates at least Fractions (1) and (2) mentioned earlier. Fraction
(1) has a lower boiling point than that of Fraction (2). When a
CDHydro is used as the Fractionation Zone of the invention,
Fraction (1) is substantially free of mercaptans-containing
compounds, with thiophenes and/or alkylthiophenes being the
predominant sulfur species. Other species such as thiophenols can
also be present in Fraction (1). When a conventional fractionation
unit (non-reactive and non-catalytic) is used as the Fractionation
Zone, Fraction (1) contains mercaptans-containing sulfur species,
which can be treated separately as discussed later below.
[0032] When using CDHydro with this invention, Fraction (2) also
comprises sulfur-containing aromatic hydrocarbons, but those sulfur
containing species have higher boiling points and include species
such as benzothiophenes and alkylbenzothiophenes as the predominant
species. Lower boiling point sulfur-containing aromatic
hydrocarbons, such as thiophene, are also present in Fraction (2),
but in the process of this invention generally are present in
relatively lesser amounts when the Fractionation Zone is run to
produce overhead having final boiling points as high as 200.degree.
C. As mentioned earlier, running the Fractionation Zone to a higher
boiling endpoint drives lower boiling point sulfur-containing
hydrocarbons into Fraction (1). Other sulfur species present in
Fraction (2) include those known as refractory sulfur compounds.
See U.S. Pat. No. 5,409,599. Substituted dibenzothiophenes and
other high molecular weight aromatic hydrocarbons are examples of
such refractory compounds. Thioether sulfur species produced from
the reaction of mercaptans and diolefins are also present in
present in Fraction (2).
[0033] Fractions (1) and (2) also contain hydrocarbons which do not
contain sulfur. Non-sulfur containing compounds include paraffins,
olefins, napthenes and cyclic olefins. Of those species, the
process of this invention drives more C.sub.6, C.sub.7, C.sub.8 and
C.sub.9 species into Fraction (1) compared to overhead generated by
the CDHydro column of the CDTECH Process. The C.sub.6-C.sub.9
species are in addition to C.sub.4 and C.sub.5 typically found in
distillation overhead from a CDHydro unit. As a result of the
fractionation conditions of this invention there are lesser amounts
of C.sub.6-C.sub.9 species in Fraction (2) compared to the bottoms
product of a CDHydro unit run at typical conditions, which in
general comprise C.sub.6, C.sub.7 and C.sub.8-C.sub.12 species.
[0034] Operating the Fractionation Zone under the above conditions
reduces the volume in the subsequent Desulfurization Zone, which in
the CDTECH Process is the capital intensive and costly to operate
CDHDS Unit. In certain embodiments of the invention, up to 70% of
the initial olefin-containing FCC naphtha feed can be driven into
the Fraction (1). Therefore, the process of this invention not only
provides a method to reduce olefin loss due to conventional
hydrodesulfurization processes, it also increases throughput
capacity in the sulfur reduction step relative to the CDHDS of the
conventional CDTECH process. These improvements can be achieved
with a more modest investment in a Membrane Separation Zone
described later below.
[0035] The equipment used to operate in the Fractionation Zone can
be one or more conventional distillation columns or towers used to
fractionate liquid streams containing a mixture of two or more
liquids having different boiling points. A CDHydro tower can be
used when running a catalytic distillation process is desired.
Conventional fractionation towers (which do not have catalyst
trays) can also be used. Equipment, which can accommodate boiling
endpoints of 70.degree. C. and higher are preferable when
processing naphtha streams from an FCC unit.
[0036] The equipment, of course, includes means to route feeds to
the Membrane Separation Zone and the Desulfurization Zone. The
process of this invention can optionally include routing Fraction
(2) to a holding tank and/or mixer in order to mix Fraction (2)
with sulfur enriched permeate from the Membrane Separation Zone
(discussed below) prior to routing the combination to the
Desulfurization Zone. Otherwise, Fraction (2) can be routed
directly to the Desulfurization Zone through a conduit that is
separate from the conduit routing the sulfur enriched permeate from
Membrane Separation Zone.
[0037] Membrane Separation Zone
[0038] When the process of this invention employs a catalytic
distillation unit such as the CDHydro unit from CDTECH, Fraction
(1) can be routed directly to the Membrane Separation Zone. In
other embodiments, e.g., when a nonreactive distillation
fractionation is used in the Fractionation Zone, Fraction (1) may
optionally be further treated before contacted with the Membrane
Separation Zone. For example, if Fraction (1) is overhead from a
nonreactive fractionator, Fraction (1) will likely contain
mercaptans-containing species in addition to thiophenes due to the
relatively lower boiling point of mercaptans and the fact these
species are not reacted to form higher molecular weight compounds
during fractionation. Accordingly, Fraction (1) can be optionally
treated with a mercaptans extraction unit prior to contact with the
Membrane Separation Zone.
[0039] Membranes useful in the present invention are those
membranes having a sufficient flux and selectivity to permeate
sulfur-containing compounds in the presence of hydrocarbons
containing sulfur and in particular, sulfur-containing naphtha,
which also contains olefin unsaturation. The membrane will
typically have a sulfur enrichment factor of greater than 1.5,
preferably greater than 2, even more preferably from about 2 to
about 20, most preferably from about 2.5 to 15. Preferably, the
membranes have an asymmetric structure, which may be defined as an
entity composed of a dense ultra-thin top "skin" layer over a
thicker porous substructure of a same or different material.
Typically, the asymmetric membrane is supported on a suitable
porous backing or support material.
[0040] In one embodiment of the invention, the membrane is a
polyimide membrane prepared from a Matrimid.RTM. 5218 or a Lenzing
polyimide polymer as described in U.S. Pat. No. 6,180,008,
incorporated herein by reference.
[0041] In another embodiment of the invention, the membrane is one
having a siloxane-based polymer as part of the active separation
layer. Typically, this separation layer is coated onto a
microporous or ultrafiltration support. Examples of membrane
structure incorporating polysiloxane functionality are found in
U.S. Pat. Nos. 4,781,733, 4,243,701, 4,230,463, 4,493,714,
5,265,734, 5,286,280 and 5,733,663, said references being herein
incorporated by reference.
[0042] In still another embodiment of the invention, the membrane
is an aromatic polyurea/urethane membrane as disclosed in U.S. Pat.
No. 4,962,271, herein incorporated by reference, which
polyurea/urethane membranes are characterized as possessing a urea
index of at least 20 % but less than 100%, an aromatic carbon
content of at least 15 mole %, a functional group density of at
least about 10 per 1000 grams of polymer, and a C.dbd.O/NH ratio of
less than about 8.
[0043] The membranes can be used in any convenient form such as
sheets, tubes or hollow fibers. Sheets can be used to fabricate
spiral wound modules familiar to those skilled in the art.
Alternatively, sheets can be used to fabricate a flat stack
permeator comprising a multitude of membrane layers alternately
separated by feed-retentate spacers and permeate spacers. This
device is described in U.S. Pat. No. 5,104,532, herein incorporated
by reference.
[0044] Tubes can be used in the form of multi-leaf modules wherein
each tube is flattened and placed in parallel with other flattened
tubes. Internally each tube contains a spacer. Adjacent pairs of
flattened tubes are separated by layers of spacer material. The
flattened tubes with positioned spacer material are fitted into a
pressure resistant housing equipped with fluid entrance and exit
means. The ends of the tubes are clamped to create separate
interior and exterior zones relative to the tubes in the housing.
Apparatus of this type is described and claimed in U.S. Pat. No.
4,761,229, herein incorporated by reference.
[0045] Hollow fibers can be employed in bundled arrays potted at
either end to form tube sheets and fitted into a pressure vessel
thereby isolating the insides of the tubes from the outsides of the
tubes. Apparatus of this type are known in the art. A modification
of the standard design involves dividing the hollow fiber bundle
into separate zones by use of baffles, which redirect fluid flow on
the tube side of the bundle and prevent fluid channeling and
polarization on the tube side. This modification is disclosed in
U.S. Pat. No. 5,169,530, herein incorporated by reference.
[0046] Multiple separation elements, be they spirally wound, plate
and frame, or hollow fiber elements can be employed either in
series or in parallel. U.S. Pat. No. 5,238,563, herein incorporated
by reference, discloses a multiple-element housing wherein the
elements are grouped in parallel with a feed/retentate zone defined
by a space enclosed by two tube sheets arranged at the same end of
the element.
[0047] The Membrane Separation Zone employs selective membrane
separation conducted under pervaporation or perstraction
conditions. Preferably, the process is conducted under
pervaporation conditions.
[0048] The pervaporation process relies on vacuum or sweep gas on
the permeate side to evaporate or otherwise remove the permeate
from the surface to the membrane. The feed is in the liquid and/or
gas state. When in the gas state the process can be described as
vapor permeation. Pervaporation can be performed at a temperature
of from about 25.degree. C. to 200.degree. C. and higher, the
maximum temperature being that temperature at which the membrane is
physically damaged. It is preferred that the pervaporation process
be operated as a single stage operation to reduce capital
costs.
[0049] The pervaporation process also generally relies on vacuum on
the permeate side to evaporate the permeate from the surface of the
membrane and maintain the concentration gradient driving force
which drives the separation process. The maximum temperature
employed in pervaporation will be that necessary to vaporize the
components in the feed which one desires to selectively permeate
through the membrane while still being below the temperature at
which the membrane is physically damaged. Alternatively to a
vacuum, a sweep gas can be used on the permeate side to remove the
product. In this mode the permeate side would be at atmospheric
pressure.
[0050] In a perstraction process, the permeate molecules in the
feed diffuse into the membrane film, migrate through the film and
reemerge on the permeate side under the influence of a
concentration gradient. A sweep flow of liquid is used on the
permeate side of the membrane to maintain the concentration
gradient driving force. The perstraction process is described in
U.S. Pat. No. 4,962,271, herein incorporated by reference.
[0051] Very significant reductions in naphtha sulfur content are
achievable by the Membrane Separation Zone and, in some cases,
sulfur reduction of 90% or better is readily achievable in the
retentate while substantially or significantly maintaining the
level of olefins initially present in the feed. Typically, the
total amount of olefin compounds present in the total Fraction (1)
is generally greater than 35 wt %, typically from about 40 to about
60 wt %. As seen in FIG. 4, the membrane used in this invention
substantially maintains the naphtha's olefin level.
[0052] Sulfur Deficient Retentate and Sulfur Deficient Permeate
[0053] The retentate from the membrane is deficient of sulfur
relative to the initial Fraction (1) routed from the Fractionation
Zone. The composition of the retentate is highly dependent on the
feedstock, the type of fractionator or other equipment employed
prior to the membrane, the membrane's sulfur enrichment factor and
the compounds that are permitted to pass through the membrane. In
typical applications, and especially those wherein FCC naphtha is
being processed, the sulfur level in the retentate is at least
below 70-ppm, and preferably below 50 ppm. In typical applications,
however, the retentate is aromatics lean compared to the
permeate.
[0054] The retentate is further processed and can be blended
downstream of the Membrane Separation Zone into gasoline, jet fuel,
heavy oil or diesel fuel.
[0055] The sulfur enriched permeate, on the other hand, is routed
to the Desulfurization Zone, and optionally blended with Fraction
(2) of the Fractionation Zone prior to entering the Desulfurization
Zone. The sulfur enriched permeate (prior to blending with any
other sulfur-containing feed) contains the sulfur species present
in Fraction (1). In typical applications, and depending on the type
of Fraction (1) membrane, separation process, etc., the permeate
will have a sulfur content of around 500-600-ppm.
[0056] Desulfurization Zone
[0057] The sulfur enriched permeate, and Fraction (2), are
contacted with a Desulfurization Zone. The Desulfurization Zone
comprises one or more processes conventionally used to reduce
and/or remove sulfur from a hydrocarbon feedstock. Conventional
processes include, but are not limited to, (1) hydrodesulfirization
processes such as used in CDHDS from CDTECH and Scanfining.TM.
process from Exxon Mobil, and (2) sulfur adsorbents such as the
S-Zorb.TM. process from Conoco Phillips. The invention is
particularly suitable for the CDHDS process, which is a catalytic
distillation hydrodesulfirization process.
[0058] Whether employing the CDHDS process, or another conventional
hydrodesulfurization process, in the Desulfurization Zone, the
sulfur enriched permeate and Fraction (2) are subjected to
hydrotreatment, which involves contacting the two with hydrogen
over a catalyst. Typical hydrotreating catalysts comprise at least
one Group VIII metal and a Group VI metal on an inorganic
refractory support, which is preferably alumina or alumina silica.
Said Groups are from the Periodic Table of the Elements, such as
that found on the last page of Advanced Inorganic Chemistry,
2.sup.nd Edition 1966, Interscience Publishers, by Cotton and
Wilkenson. The Group VIII metal is present in an amount ranging
from about 2 to 20 wt %, preferably from about 10 to 40 wt % and
more preferably from about 20 to 30 wt %. All metals weight
percents are on support. By "on support" it is meant that the
percents are based on the weight of the support. For example, if
the support were to weigh 100 g. then 20 wt % Group VIII metal
would mean that 20 g. of Group VIII metal was on the support.
[0059] Any suitable inorganic oxide support material may be used
for the catalyst. Preferred are alumina and silica-alumina. More
preferred is alumina. The silica content of the silica-alumina
support can be from about 2 to 30 wt %, preferably 3 to 20 wt %,
more preferably 5 to 19 wt %. Other refractory inorganic compounds
may also be used, examples of which include, but are not limited
to, zirconia, titania, magnesia, and the like. The alumina can be
any of the aluminas conventionally used for hydrotreating catalyst.
Such aluminas are generally porous amorphous alumina having an
average pore size from about 50 to 200 .ANG., preferably from about
70 to 150 .ANG., and a surface area from about 50 to about 450
m.sup.2/g (as measured by BET), preferably from about 100 to 300
m.sup.2/g.
[0060] As previously stated, hydrotreatment is performed in the
presence of hydrogen. Either pure or plant hydrogen may be
employed, so long as the stream contains at least about 50%
hydrogen.
[0061] Hydrotreatment is conducted at a temperature in the range of
about 200.degree. to 400.degree. C., preferably about 330 to
400.degree. C., at a pressure in the range of about 250 to 2500
psig, preferably about 300 to 2000 psig, at a hydrogen treat gas
rate in the range of about 500 to 8000 SCF/B, preferably about 500
to 6000 SCF/B, at a space velocity in the range 0.2 to 6 LLHSV,
preferably 0.3 to 1.0 LHSV.
[0062] The effluent from the Desulfurization Zone is reduced in
sulfur and nitrogen content and in metals. Hydrotreatment also
effects the hydrogenation of olefinic and aromatic unsaturated
materials, but in this invention the hydrogenation of olefins is
reduced due to more olefins being driven into Fraction (1) of the
Fractionation Zone.
[0063] When employing a sulfur adsorption process in the
Desulfurization Zone, the sulfur enriched permeate and Fraction (2)
are combined with a small hydrogen stream and heated to a vaporized
stream. The vaporized stream is injected into an expanded fluid-bed
reactor, where the sorbent removes sulfur from the feed. A
disengaging zone in the reactor removes suspended sorbent from the
vapor, which exits the reactor to be cooled. The sorbent is
continuously withdrawn from the reactor and transferred to the
regenerator section (2), where the sulfur is removed as SO.sub.2
and sent to a sulfur-recovery unit. The cleansed sorbent is
reconditioned and returned to the reactor. The rate of sorbent
circulation is controlled to help maintain the desired sulfur
concentration in the product. Sorbents used in these processes are
well known and include nickel, alumina and/or zinc oxide-containing
catalysts.
[0064] The general operating conditions of a sulfur adsorption
process follow:
1 Temperature, .degree. F. 650-775 Pressure, psig 100-300 Space
velocity, whsv 4-10 Hydrogen purity, % 70-99 Total H.sub.2 usage,
scf/bbl 40-60
[0065] The Desulfurization Zone can comprise one or more of the
units described above or combination of different desulfurization
units. The effluent from the Desulfurization Zone is then further
processed and/or blended to form gasoline blend product.
[0066] Potential benefits of the invention beyond those mentioned
earlier include (but are not limited to):
[0067] 1. Modular design (expandability and ease of
construction)--The Membrane Separation Zone can be modular in
nature and readily scaleable compared to, e.g., a CDHDS tower.
Equipment for the Membrane Separation Zone can include membrane
modules (housing approximately 1000 m.sup.2 of membrane surface
area per 6 meter long.times.2 meter diameter shell and tube
module), condensers, refrigeration system, vacuum pump and feed
pumps. Additional modules can be added with minor piping
modifications.
[0068] 2. Long on-stream time due to ease of maintenance (module
replacements)--During operation, banks of modules can be blocked
off and module-tubes (one piece) can be pulled and replaced. This
will allow for long runs and periodic replacement of membrane to
maintain/improve sulfur removal performance.
[0069] 3. Low operating temperature--Since the process in the
Membrane Separation Zone can operate at low temperatures
(90-120.degree. C.) fired heaters are not required to heat Fraction
(1) to process conditions. This reduces operating costs.
[0070] 4. No recombination reactions--Since the Membrane Separation
Zone does not generate H.sub.2S and it operates at low temperature
and pressure, olefins/H.sub.2S recombination reactions do not
usually occur.
[0071] 5. Aromatics (benzene) removal--While not a primary benefit
of employing a Membrane Separation Zone, the retentate aromatics
level (particularly benzene) is substantially reduced by the
process. If lower gasoline benzene specifications are required, the
invention presents an opportunity for cost-effectively removing
benzene/aromatics, e.g. through the permeate.
[0072] 6. Retentate is easier to blend downstream--The sulfur
deficient retentate from the Membrane Separation Zone is a higher
boiling point stream compared to overhead from a CDHydro unit
operated under its conventional conditions. Accordingly, when a
CDHydro unit is employed as the Fractionation Zone of this
invention, the invention drives a Fraction (1) from the unit that
has a boiling point greater than 100.degree. C. The boiling point
of the effluent from the Membrane Separation Zone is typically the
same as that of Fraction (1). Accordingly, the effluent has a lower
vapor pressure, thereby making the effluent easier to handle and
blend downstream to make a finished gasoline.
EXAMPLES
Example 1
Fraction (1)
[0073] An overhead from a CDHydro Unit having a final boiling point
of in the range of 100-300.degree. F. was obtained for further
separation through a Membrane Separation Zone according to the
invention. The content of the overhead had the composition
indicated in the Table below.
2 CD Hydro Composition Overhead ppm S Mercaptans 11.1 Thiophene
96.2 Methyl Thiophenes 19.5 Tetrahydro Thiophene 2.0 C2-Thiophenes
0.0 Thiophenol 0.0 C3-Thiophenes 0.0 Methyl Thiophenol 0.0
C4-Thiophenes 0.0 Unidentified Sulfur Species 0.0 Benzo Thiophene
0.0 AlkylBenzo Thiophene 0.0 Total 128.8
Example 2
Membrane
[0074] A polyurea-urethane membrane is prepared as follows.
[0075] A polyurea/urethane (PUU) composite membrane is formed
through coating of a porous substrate following the methods of U.S.
Pat. No. 4,921,611. To a solution of 0.7866 g of toluene
diisocyanate terminated polyethylene adipate (Aldrich Chemical
Company, Milwaukee, Wis.; Cat. #43, 351-9) in 9.09 g of p-dioxane
is added 0.1183 g of 4-4'-methylene dianiline (Aldrich; #13,245-4)
dissolved in 3.00 g p-dioxane. When the solution began to gel it is
coated with a blade gap set 3.6 mil above a 0.2 micron pore size
microporous polytetrafluoroethylene (PTFE) membrane (W. L. Gore,
Elkton, Md.). The solvent evaporates to give a continuous film. The
composite membrane is then heated in an oven 100.degree. C. for one
hour. The final composite membrane structure has a PUU coating 3
microns thick measured by scanning electron microscopy. The
membrane shows an enrichment factor of 7.53 for thiophen and 3.15
for mercaptans.
[0076] The membrane is then formed into flat sheets for testing
purposes.
Example 3
Membrane Separation Zone
[0077] The overhead from Example 1 was pumped into a Membrane
Separation Zone containing a membrane prepared according to Example
2. The separation was conducted under pervaporation conditions.
Specifically, the overhead was pumped at an average flux (kilograms
per square meter per hour) and temperature (C..degree.) illustrated
in FIG. 2.
[0078] FIG. 3 shows the sulfur content in parts per million (ppm)
in the membrane retentate as permeate is collected in amounts based
on overhead content. This data is plotted with (.diamond-solid.).
FIG. 3 also shows the percentage of sulfur reduction at each plot
of sulfur content. Briefly, this graph shows that over 75% sulfur
reduction and levels of less than 25 ppm sulfur can be obtained
while maintaining at least 70% of the original overhead, thereby
leaving 30% of the overhead that has to be routed to the sulfur
reduction zone of the invention.
[0079] FIG. 4 shows that the olefin distribution of the overhead
feed is significantly maintained after a 29.4% stage cut with only
some loss shown for C.sub.5 olefins (O5). 06, 07 and 08 correspond
to C.sub.6, C.sub.7 and C.sub.8 olefin content of the retentate
relative to the feed.
* * * * *